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CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

 

All statements, other than historical fact or present financial information, may be deemed to be forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, (“Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended. All statements that address activities, outcomes and other matters that should or may occur in the future, including, without limitation, statements regarding the financial position, business strategy, production and reserve growth and other plans and objectives for our future operations, are forward-looking statements. Although we believe the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance. We have no obligation and make no undertaking to publicly update or revise any forward-looking statements, except as may be required by law.

 

Forward-looking statements include the items identified in the preceding paragraph, information concerning possible or assumed future results of operations and other statements in this Form 10-Q identified by words such as “anticipate,” “project,” “intend,” “estimate,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “plan,” “forecast,” “target” or similar expressions.

 

You should not place undue reliance on forward-looking statements. They are subject to known and unknown risks, uncertainties and other factors that may affect our operations, markets, products, services and prices and cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with forward-looking statements, risks, uncertainties and factors that could cause our actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:

 

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We caution you that forward-looking statements contained in this Form 10-Q are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of natural gas and oil. These risks include, but are not limited to, commodity price volatility, third-party interruption of sales to market, inflation, lack of availability of goods and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating proved natural gas and oil reserves and in projecting future rates of production and timing of development expenditures and the other risks described in our Annual Report on Form 10-K for the year ended December 31, 2013 (the “2013 Annual Report on Form 10-K”), and all quarterly reports on Form 10-Q filed subsequently thereto, including this Form 10-Q (“Form 10-Qs”).

 

Should one or more of the risks or uncertainties described above or elsewhere in this Form 10-Q occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages.

 

All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.

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PART I – FINANCIAL INFORMATION

 

ITEM 1. FINANCIAL STATEMENTS.

 

 

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

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The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

 

 

 

 

 

 

 

 

 

 

 

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The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

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The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

(1) BASIS OF PRESENTATION

 

Southwestern Energy Company (including its subsidiaries, collectively, “we”, “Southwestern” or the “Company”) is an independent energy company engaged in natural gas and oil exploration, development and production. The Company engages in natural gas and oil exploration and production, natural gas gathering and natural gas marketing through its subsidiaries. Southwestern’s exploration, development and production (“E&P”) activities are focused within the United States.   The Company is actively engaged in exploration and production activities in Arkansas, where we are targeting the unconventional gas reservoir known as the Fayetteville Shale, in Pennsylvania, where we are targeting the unconventional gas reservoir known as the Marcellus Shale, and to a lesser extent in Texas and in Arkansas and Oklahoma in the Arkoma Basin.  The Company also actively seeks to find and develop new oil and natural gas plays with significant exploration and exploitation potential. Southwestern’s natural gas gathering and marketing (“Midstream Services”) activities primarily support the Company’s E&P activities in Arkansas, Pennsylvania, Louisiana and Texas.  

 

The accompanying unaudited condensed consolidated financial statements were prepared using accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and in accordance with the rules and regulations of the Securities and Exchange Commission. Certain information relating to the Company’s organization and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been appropriately condensed or omitted in this Quarterly Report on Form 10-Q. The Company believes the disclosures made are adequate to make the information presented not misleading.

 

The unaudited condensed consolidated financial statements contained in this report include all normal and recurring material adjustments that, in the opinion of management, are necessary for a fair statement of the financial position, results of operations and cash flows for the interim periods presented herein. It is recommended that these unaudited condensed consolidated financial statements be read in conjunction with the consolidated financial statements and the notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2013 (“2013 Annual Report on Form 10-K”).

 

The Company’s significant accounting policies, which have been reviewed and approved by the Audit Committee of the Company’s Board of Directors, are summarized in Note 1 in the Notes to the Consolidated Financial Statements included in the Company’s 2013 Annual Report on Form 10-K.

 

Certain reclassifications have been made to the prior year financial statements to conform to the 2014 presentation. The effects of the reclassifications were not material to the Company’s unaudited condensed consolidated financial statements.

 

 

 

(2) ACQUISITIONS AND DIVESTITURES

 

In March 2014, the Company signed an agreement to purchase approximately 312,000 net acres in northwest Colorado principally in the Niobrara formation for approximately $180 million, subject to closing adjustments. The Company utilized its Credit Facility to finance the acquisition. The Company closed on the acquisition on May 1, 2014 and plans to account for it as an asset acquisition.

 

In April 2013, the Company entered into a definitive purchase agreement to acquire natural gas properties located in Pennsylvania prospective for the Marcellus Shale for approximately $93 million, subject to closing conditions.  The Company utilized its revolving credit facility to finance the acquisition.  The Company closed on the acquisition during the second quarter of 2013 and accounted for it as an asset acquisition.

 

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(3) PREPAID EXPENSES

 

The components of prepaid expenses included in other current assets as of March 31, 2014 and December 31, 2013 consisted of the following:

 

 

(4) INVENTORY

 

Inventory recorded in current assets includes $2.3 million at March 31, 2014 and $3.7 million at December 31, 2013 for natural gas in underground storage owned by the Company’s E&P segment, and $36.4 million at March 31, 2014 and $34.1 million at December 31, 2013 for tubular and other equipment used in the E&P segment.

 

Other long-term assets include $17.0 million at March 31, 2014 and $15.1 million at December 31, 2013, respectively, for inventory held by the Midstream Services segment consisting primarily of pipe that will be used to construct gathering systems.

 

(5) NATURAL GAS AND OIL PROPERTIES

 

The Company utilizes the full cost method of accounting for costs related to the exploration, development and acquisition of natural gas and oil reserves. Under this method, all such costs (productive and nonproductive), including salaries, benefits and other internal costs directly attributable to these activities are capitalized on a country by country basis and amortized over the estimated lives of the properties using the units-of-production method. These capitalized costs, less accumulated amortization and related deferred income taxes, are subject to a ceiling test that limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved natural gas and oil reserves, net of taxes, discounted at 10 percent plus the lower of cost or market value of unproved properties. Any costs in excess of the ceiling are written off as a non-cash expense. The expense may not be reversed in future periods, even though higher natural gas and oil prices may subsequently increase the ceiling. Full cost companies must use the average quoted price from the first day of each month from the previous 12 months, including the impact of derivatives qualifying as cash flow hedges, to calculate the ceiling value of their reserves.

 

Using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $3.99 per MMBtu and $94.92 per barrel for West Texas Intermediate oil, adjusted for market differentials, the Company’s net book value of its United States natural gas and oil properties did not exceed the ceiling amount and did not result in a ceiling test impairment at March 31, 2014. Cash flow hedges of natural gas production in place increased the ceiling value by $40.2 million, net of tax, at March 31, 2014.  Decreases in average quoted prices from March 31, 2014 levels as well as changes in production rates, levels of reserves, capitalized costs, the evaluation of costs excluded from amortization, future development costs, service costs and taxes could result in future ceiling test impairments.

 

Using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $2.95 per MMBtu and $89.17 per barrel for West Texas Intermediate oil, adjusted for market differentials, the Company’s net book value of its United States natural gas and oil properties did not exceed the ceiling amount and did not result in a ceiling test impairment at March 31, 2013. Cash flow hedges of natural gas production in place increased the ceiling by $185.8 million at March 31, 2013.

 

All of the Company’s costs directly associated with the acquisition and evaluation of properties in Canada relating to its exploration program at March 31, 2014 were unproved and did not exceed the ceiling amount.  If the exploration program in Canada is unsuccessful on all or a portion of these properties, a ceiling test impairment may result in the future.

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(6) EARNINGS PER SHARE

 

Basic EPS is computed by dividing net income (the numerator) by the weighted-average number of common shares outstanding for the period (the denominator). Diluted EPS is similarly calculated except that the denominator is increased using the treasury stock method to reflect the potential dilution that could occur if outstanding stock options were exercised and unvested restricted stock and performance unit awards were vested at the end of the applicable period.

 

The following table presents the computation of earnings per share for the three month period ended March 31, 2014 and 2013:

 

 

 

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(7) DERIVATIVES AND RISK MANAGEMENT

 

The Company is exposed to volatility in market prices and basis differentials for natural gas and crude oil which impacts the predictability of its cash flows related to the sale of natural gas and oil, and is exposed to volatility in interest rates. These risks are managed by the Company’s use of certain derivative financial instruments.  At March 31, 2014 and December 31, 2013, the Company’s derivative financial instruments consisted of fixed price swaps, basis swaps, fixed price call options, and interest rate swaps. A description of the Company’s derivative financial instruments is provided below:

 

 

GAAP requires that all derivatives be recognized in the balance sheet as either an asset or liability and be measured at fair value other than transactions for which normal purchase/normal sale is applied. Under GAAP, certain criteria must be satisfied in order for derivative financial instruments to be classified and accounted for as either a cash flow or a fair value hedge. Accounting for qualifying hedges requires a derivative’s gains and losses to be recorded either in earnings or as a component of other comprehensive income. Gains and losses on derivatives that are not elected for hedge accounting treatment or that do not meet hedge accounting requirements are recorded in earnings as a component of gain (loss) on derivatives. Within the gain (loss) on derivatives component of the statement of operations are gains (losses) on derivatives, net of settlement and gains (losses) on derivatives, settled. The Company calculates gains (losses) on derivatives, settled, as the summation of gains and losses on positions which have settled within the period.

 

The Company utilizes counterparties for its derivative instruments that it believes are credit-worthy at the time the transactions are entered into and the Company closely monitors the credit ratings of these counterparties. Additionally, the Company performs both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable. However, the events in the financial markets in recent years demonstrate there can be no assurance that a counterparty will be able to meet its obligations to the Company.

 

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The balance sheet classification of the assets related to derivative financial instruments are summarized below at March 31, 2014 and December 31, 2013:

 

 

As of March 31, 2014, the Company had derivatives designated as cash flow hedges and derivatives not designated as hedges on the following volumes of natural gas production (in Bcf):

 

 

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Cash Flow Hedges

 

The reporting of gains and losses on cash flow derivative hedging instruments depends on whether the gains or losses are effective at offsetting changes in the cash flows of the hedged item. The effective portion of the gains and losses on the derivative hedging instruments are recorded in other comprehensive income until recognized in earnings during the period that the hedged transaction takes place. The ineffective portion of the gains and losses from the derivative hedging instrument is recognized in earnings immediately.

 

As of March 31, 2014, the Company recorded a net loss in accumulated other comprehensive income related to its hedging activities of $18.6 million net of a deferred income tax benefit of $12.4 million. The amount recorded in accumulated other comprehensive income will be relieved over time and recognized in the statement of operations as the physical transactions being hedged occur. Assuming the market prices of natural gas futures as of March 31, 2014 remain unchanged, the Company would expect to transfer an aggregate after-tax net loss of $18.6 million from accumulated other comprehensive income to earnings during the next 12 months. Gains or losses from derivative instruments designated as cash flow hedges are reflected as adjustments to natural gas sales in the consolidated statements of operations. Volatility in net income, comprehensive income and comprehensive income may occur in the future as a result of the Company’s derivative activities.

 

The following tables summarize the before tax effect of all cash flow hedges on the unaudited condensed consolidated financial statements for the three-month period ended March 31, 2014 and 2013:

 

 

 

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Fair Value Hedges and Other Derivative Contracts

 

For fair value hedges, the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item are recognized in earnings immediately. 

 

Although the Company’s basis swaps meet the objective of managing commodity price exposure, these trades are typically not entered into concurrent with the Company’s derivative instruments that qualify as cash flow hedges and therefore do not generally qualify for hedge accounting. Basis swap derivative instruments that are not designated for hedge accounting are recorded on the balance sheet at their fair values under derivative assets, other long-term assets, other current liabilities, and other long-term liabilities, as applicable and all gains and losses related to these contracts are recognized immediately in the consolidated statement of operations as a component of gain (loss) on derivatives.

 

As of March 31, 2014, the Company had basis swaps on natural gas production that were not designated for hedge accounting of 21.1 Bcf, 8.7 Bcf, and 0.9 Bcf in 2014, 2015, and 2016, respectively.

 

As of March 31, 2014, the Company had fixed price call options on 199.8 Bcf and 119.9 Bcf of 2015 and 2016 natural gas production, respectively, not designated for hedge accounting treatment and fixed price swaps of 136.8 Bcf and 119.5 Bcf of 2014 and 2015 natural gas production not designated for hedge accounting.

 

The Company is a party to interest rate swaps that were entered into in order to mitigate the Company’s exposure to volatility in interest rates related to construction of its new corporate office complex. The interest rate swaps build to a notional amount of $170.0 million and expire on June 20, 2020. The Company did not designate the interest rate swaps for hedge accounting.  Changes in the fair value of the interest rate swaps are included in gain (loss) on derivatives in the consolidated statements of operations.

 

The following table summarizes the before tax effect of fair value hedges, fixed price call and basis swaps that were not designated for hedge accounting, and fixed price swaps and interest rate swaps not designated for hedge accounting on the uncondensed consolidated statements of operations for the three-month period ended March 31, 2014 and 2013:

 

 

 

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(8) RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE LOSS

 

The following tables detail the components of accumulated other comprehensive loss and the related tax effects for the three months ended March 31, 2014:

 

 

 

 

The following table details the amounts reclassified from accumulated other comprehensive loss into earnings for the three months ended March 31, 2014:

 

 

 

 

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(9) FAIR VALUE MEASUREMENTS

 

The carrying amounts and estimated fair values of the Company’s financial instruments as of March 31, 2014 and December 31, 2013 were as follows:

 

 

The carrying values of cash and cash equivalents, accounts receivable, accounts payable, other current assets and current liabilities on the unaudited condensed consolidated balance sheets approximate fair value because of their short-term nature. For debt and derivative instruments, the following methods and assumptions were used to estimate fair value:

 

Debt: The fair values of the Company’s senior notes were based on the market for the Company’s publicly-traded debt as determined based on yield of the Company’s 7.5% Senior Notes due 2018, which was 2.4% at March 31, 2014 and 2.6% at December 31, 2013, and its 4.10% Senior Notes due 2022, which was 3.7% at March 31, 2014, and 4.2% at December 31, 2013. The carrying value of the borrowings under the Company’s Credit Facility at March 31, 2014, approximate fair value because the interest rate is variable and reflective of market rates.  The Company considers the fair value of its debt to be a Level 2 measurement on the fair value hierarchy. 

 

Derivative Instruments: The fair value of all derivative instruments is the amount at which the instrument could be exchanged currently between willing parties. The amounts are based on quoted market prices, best estimates obtained from counterparties and an option pricing model, when necessary, for price option contracts.

 

GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. As presented in the tables below, this hierarchy consists of three broad levels:

 

Level 1 valuations - Consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority.

 

Level 2 valuations - Consist of quoted market information for the calculation of fair market value.

 

Level 3 valuations - Consist of internal estimates and have the lowest priority.

 

The Company has classified its derivatives into these levels depending upon the data utilized to determine their fair values. The Company’s Level 2 fair value measurements include fixed-price swaps and are estimated using internal discounted cash flow calculations using the NYMEX futures index. The Company utilizes discounted cash flow models for valuing its interest rate derivatives. The net derivative values attributable to the Company's interest rate derivative contracts as of March 31, 2014 are based on (i) the contracted notional amounts, (ii) active market-quoted London Interbank Offered Rate (“LIBOR”) yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. The Company's interest rate derivative asset and liability measurements represent Level 2 inputs in the hierarchy. The Company’s Level 3 fair value measurements include fixed price call options and basis swaps. The Company’s fixed price call options are valued using the Black-Scholes model, an industry standard option valuation model, and takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the NYMEX futures index, interest rates, volatility and credit worthiness.  The Company’s basis swaps are estimated using internal discounted cash flow calculations based upon forward commodity price curves. 

 

Inputs to the Black-Scholes model, including the volatility input, which is the significant unobservable input for Level 3 fair value measurements, are obtained from a third-party pricing source, with independent verification of most significant inputs on a monthly basis. An increase (decrease) in volatility would result in an increase (decrease) in fair value measurement, respectively.

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Assets and liabilities measured at fair value on a recurring basis are summarized below (in thousands):

 

 

The table below presents reconciliations for the change in net fair value of derivative assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the three-month periods ended March 31, 2014 and March 31, 2013. The fair values of Level 3 derivative instruments are estimated using proprietary valuation models that utilize both market observable and unobservable parameters. Level 3 instruments presented in the table consist of net derivatives valued using pricing models incorporating assumptions that, in the Company’s judgment, reflect the assumptions a reasonable marketplace participant would have used at March  31, 2014 and March 31, 2013.

 

 

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(10) DEBT

 

The components of debt as of March 31, 2014 and December 31, 2013 consisted of the following:

 

 

Credit Facility 

 

On December 16, 2013, the Company entered into a Credit Agreement (“Credit Facility”), which exchanged our previous revolving credit facility.  Under the Credit Facility, we have a borrowing capacity of  $2.0 billion. The Credit Facility has a maturity date in December 2018 and options for two one-year extensions with participating lender approval.  The amount available under the Credit Facility may be increased by  $500.0  million upon the Company’s agreement with its participating lenders. The interest rate on the Credit Facility is calculated based upon our credit rating and is currently 150 basis points over the current LIBOR. The borrowing rate on our previous revolving credit facility was 200 basis points over LIBOR. The Credit Facility is unsecured and is not guaranteed by any subsidiaries of the Company.  The Credit Facility contains covenants that impose certain restrictions on the Company, including a financial covenant whereby the Company may not issue total debt in excess of 60% of its total adjusted book capital. This financial covenant with respect to capitalization percentages excludes the effects of any full cost ceiling impairments (after December 31, 2011), certain hedging activities and our pension and other postretirement liabilities. As of March 31, 2014, the Company was in compliance with the covenants of its Credit Facility and other debt agreements.  Although the Company believes all of the lenders under the Credit Facility have the ability to provide funds, it cannot predict whether each will be able to meet its obligation under the facility.

 

(11) COMMITMENTS AND CONTINGENCIES

 

Commitments

 

In the first quarter of 2010, the Company was awarded exclusive licenses by the Province of New Brunswick in Canada to conduct an exploration program covering approximately 2.5 million acres in the province. The licenses require the Company to make certain capital investments in New Brunswick of approximately $47.0 million Canadian dollars in the aggregate over a three year period. In order to obtain the licenses, the Company provided promissory notes payable on demand to the Minister of Finance of the Province of New Brunswick with an aggregate principal amount of $44.5 million Canadian dollars. The promissory notes secure the Company's capital expenditure obligations under the licenses and are returnable to the Company to the extent the Company performs such obligations. If the Company fails to fully perform, the Minister of Finance may retain a portion of the applicable promissory notes in an amount equal to any deficiency. The Company commenced its Canada exploration program in 2010 and, as of March 31, 2014 has invested $42.2 million Canadian dollars, or $38.2 million USD, in New Brunswick towards the Company’s commitment.  In December 2012, the Company received two one-year extensions to our exploration license agreements, the second of which will expire on March 16, 2015.  No liability has been recognized in connection with the promissory notes due to the Company’s investments in New Brunswick as of March 31, 2014 and its future investment plans.  

 

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The Company entered into new and amended natural gas transportation and gathering arrangements with third party pipelines, during the second quarter of 2013, in support of the Company’s production in the Marcellus Shale.  As of March 31, 2014, the Company’s obligations for demand and similar charges under the firm transportation agreements and gathering agreements totaled approximately $3.6 billion and the Company has guarantee obligations of up to $100.0 million of that amount.  

 

Environmental Risk

 

The Company is subject to laws and regulations relating to the protection of the environment. Environmental and cleanup related costs of a non-capital nature are accrued when it is both probable that a liability has been incurred and when the amount can be reasonably estimated. Management believes any future remediation or other compliance related costs will not have a material effect on the financial position or reported results of operations of the Company.

 

Litigation

 

Tovah Energy

 

In February 2009, Southwestern Energy Production Company (“SEPCO”) was added as a defendant in a case then styled Tovah Energy, LLC and Toby Berry-Helfand v. David Michael Grimes, et, al., pending in the 273rd District Court in Shelby County, Texas. By the time of trial in December 2010, Ms. Berry-Helfand (the only remaining plaintiff) alleged that, in 2005, she provided SEPCO with proprietary data regarding two prospects in the James Lime formation pursuant to a confidentiality agreement and that SEPCO refused to return the proprietary data to the plaintiff, subsequently acquired leases based upon such proprietary data and profited therefrom. Among other things, she alleged various statutory and common law claims, including, but not limited to, claims of misappropriation of trade secrets, violation of the Texas Theft Liability Act, breach of fiduciary duty and confidential relationships, various fraud based claims and breach of contract, including a claim of breach of a purported right of first refusal on all interests acquired by SEPCO between February 2005 and February 2006. She also sought disgorgement of SEPCO’s profits. A former associate of the plaintiff intervened in the matter claiming to have helped develop the prospect years earlier.

 

The jury found in favor of the plaintiff and the intervenor with respect to all of the statutory and common law claims and awarded $11.4 million in compensatory damages but no special, punitive or other damages. Separately, the jury determined that SEPCO’s profits for purposes of disgorgement, if ordered as a remedy, were $381.5 million. (Disgorgement of profits is an equitable remedy determined by the judge, and it is within the judge’s discretion to award none, some or all of unlawfully obtained profits.) In August 2011, a judgment was entered pursuant to which the plaintiff and the intervenor were entitled to recover approximately $11.4 million in actual damages and approximately $23.9 million in disgorgement as well as prejudgment interest and attorneys’ fees, which currently are estimated to be up to $8.9 million, and all costs of court of the plaintiff and intervenor.

 

Both sides appealed and in July 2013, the Tyler Court of Appeals ordered that (1) the judgment awarding the plaintiff and the intervenor $23.9 million as disgorgement of illicit gains be reversed and judgment rendered that they take nothing, (2) the award of $11.4 million for actual damages, insofar as it is based on the jury’s findings of breach of fiduciary duty, fraud, breach of contract, and theft of trade secret is reversed and judgment rendered that the plaintiff and the intervenor take nothing under those theories of recovery, (3) the award of $11.4 million to the plaintiff and the intervenor as damages for misappropriation of trade secret is affirmed, (4) the case be remanded to the trial court for a determination and award of attorney’s fees for SEPCO as the prevailing party under the Texas Theft Liability Act, and (5) in all other respects, the judgment is affirmed. All parties petitioned for rehearing. The Tyler Court of Appeals denied rehearing in November 2013.

 

SEPCO filed a petition for review in the Supreme Court of Texas in February 2014. The plaintiff and the intervenor filed cross-petition for review in April 2014, but conditioned their filing on the court’s granting SEPCO’s petition for review; i.e., if the court denies SEPCO’s petition for review, then the plaintiff and the intervenor are not seeking further review of the court of appeals’ judgment. Based on the Company’s understanding and judgment of the facts and merits of this case, including appellate matters, and after considering the advice of counsel, the Company has determined that, although reasonably possible, a materially adverse final outcome to this action is not probable. As such, the Company has not accrued any amounts with respect to this action. If the Supreme Court declines to hear the case or affirms all aspects of the court of appeals’ judgment, then SEPCO would owe the $11.4 million in damages, plus interest and attorneys fees, offset by any award of attorneys’ fees for its prevailing on the theft count. The Company’s assessment may change in the future due to occurrence of certain events, such as the result of the petition or petitions for review at the Supreme Court of Texas, and such a re-assessment could lead to the determination that the potential liability is probable and could be material to the Company’s results of operations, financial position or cash flows. 

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Other

 

The Company is subject to various litigation, claims and proceedings that have arisen in the ordinary course of business, such as for alleged breaches of contract, miscalculation of royalties and pollution, contamination or nuisance. Management believes that such litigation, claims and proceedings, individually or in aggregate and after taking into account insurance, are not likely to have a material adverse impact on our financial position, results of operations or cash flows. Many of these matters are in early stages, so the allegations and the damage theories have not been fully developed, and all subject to inherent uncertainties; therefore, management’s view may change in the future. If an unfavorable final outcome were to occur, there exists the possibility of a material impact on the Company’s financial position, results of operations or cash flows for the period in which the effect becomes reasonably estimable. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated.

 

(12) SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION

 

Supplemental disclosures of cash flow information:

 

 

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(13) PENSION PLAN AND OTHER POSTRETIREMENT BENEFITS

 

The Company has defined pension and postretirement benefit plans which cover substantially all of the Company’s employees. Net periodic pension and other postretirement benefit costs include the following components for the three  month periods ended March 31, 2014 and 2013:  

 

 

As of March 31, 2014, the Company has contributed $3.0 million to the pension plan,  and expects to contribute an additional $9.0 million to the pension plan in 2014.

 

The Company maintains a non-qualified deferred compensation supplemental retirement savings plan (“Non-Qualified Plan”) for certain key employees who may elect to defer and contribute a portion of their compensation, as permitted by the plan. Shares of the Company’s common stock purchased under the terms of the Non-Qualified Plan are presented as treasury stock and totaled 10,608 shares at March 31, 2014 compared to 9,924 shares at December 31, 2013.

 

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(14) STOCK-BASED COMPENSATION

 

The Company recognized the following amounts in employee stock-based compensation costs for the three months ended March 31, 2014 and 2013:

 

 

As of March 31, 2014, there was $81.7 million of total unrecognized compensation cost related to the Company’s unvested stock option grants, restricted stock grants, and performance units. This cost is expected to be recognized over a weighted-average period of 3.4 years.

 

The following table summarizes stock option activity for the three months ended March 31, 2014 and provides information for options outstanding and options exercisable as of March 31, 2014:

 

 

The following table summarizes restricted stock activity for the three months ended March 31, 2014 and provides information for unvested shares as of March 31, 2014:

 

 

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The following table summarizes performance unit activity for the three months ended March 31, 2014 and provides information for unvested units as of March 31, 2014.    The performance units include a market condition based on Relative Total Shareholder Return (“TSR”) and a performance condition based on the Company's Present Value Index (“PVI”). The fair value of the TSR market condition of the performance units is based on a Monte Carlo model and is amortized to compensation expense on a straight-line basis over the vesting period of the award. The fair value of the PVI performance condition of the performance units is based on the closing price of the Company's common stock at the grant date and amortized to compensation expense on a straight line basis over the vesting period of the award. 

 

 

 

Liability-Classified Performance Units

 

Certain employees were provided performance units vesting equally over three years.  The payout of these units is based on certain metrics, such as total shareholder return and reserve replacement efficiency, compared to a predetermined group of peer companies and Company goal.  At the end of each performance period, the value of the vested performance units, if any, is paid in cash.  As of March 31, 2014 and December 31, 2013, the Company's liability under the performance unit agreements was $34.7 million and $45.3 million, respectively.

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(15) SEGMENT INFORMATION

 

The Company’s reportable business segments have been identified based on the differences in products or services provided. Revenues for the E&P segment are derived from the production and sale of natural gas and crude oil. The Midstream Services segment generates revenue through the marketing of both Company and third-party produced natural gas volumes and through gathering fees associated with the transportation of natural gas to market.

 

Summarized financial information for the Company’s reportable segments is shown in the following table. The accounting policies of the segments are the same as those described in Note 1 of the Notes to Consolidated Financial Statements included in Item 8 of the 2013 Annual Report on Form 10-K. Management evaluates the performance of its segments based on operating income, defined as operating revenues less operating costs. Income before income taxes, for the purpose of reconciling the operating income amount shown below to consolidated income before income taxes, is the sum of operating income, interest expense and interest and other income (loss). The “Other” column includes items not related to the Company’s reportable segments including real estate and corporate items.

 

 

 

Included in intersegment revenues of the Midstream Services segment are $823.5 million and $419.5 million for the three months ended March 31, 2014 and 2013, respectively, for marketing of the Company’s E&P sales. Corporate assets include cash and cash equivalents, furniture and fixtures, prepaid debt and other costs. Corporate general and administrative costs, depreciation expense and taxes other than income are allocated to the segments. For the three months ended March 31, 2014 and 2013, capital investments within the E&P segment include $4.1 million and $2.3 million, respectively, related to the Company’s activities in Canada.  At March 31, 2014, E&P segment assets include $79.9 million and at March 31, 2013, assets include $45.9  million related to the Company’s activities in Canada.

 

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(16) CONDENSED CONSOLIDATING FINANCIAL INFORMATION

 

As of December 16, 2013, following the release of all guarantees under the 7.15%, 7.5%, 7.35%, 7.125%, and 4.10% Senior Notes and our former revolving credit facility upon entering into the new Credit Facility, all of our wholly-owned subsidiaries have been released of their guarantees.

 

Prior to that date, the Company’s obligation under registered public debt and outstanding senior notes as listed in Note 10 were fully and unconditionally guaranteed, jointly and severally, by all of our wholly-owned subsidiaries, other than minor subsidiaries, on a senior unsecured basis, and the Company, as a parent company, had no independent assets or operations. The subsidiary guarantees (i) rank equally in right of payment with all of the existing and future senior debt of the subsidiary guarantors; (ii) rank senior to all of the existing and future subordinated debt of the subsidiary guarantors; (iii) were effectively subordinated to any future secured obligations of the subsidiary guarantors to the extent of the value of the assets securing such obligations; and (iv) were structurally subordinated to all debt and other obligations of the subsidiaries of the guarantors. In the case of each series of notes, if no default or event of default had occurred and was continuing, these guarantees would be released (i) automatically upon any sale, exchange or transfer of all the Company’s interest in the guarantor; (ii) automatically upon the liquidation and dissolution of a guarantor; (iii) following delivery of notice to the trustee of the release of the guarantor of its obligation under the Company’s revolving credit facility; and (iv) upon legal or covenant defeasance or other satisfaction of the obligations under the notes, in addition, there were no significant restrictions on the ability of the Company or a guarantor to obtain funds from its subsidiaries by dividend or loan, and none of the assets of the Company or a guarantor represented restricted net assets pursuant to rule 4-08(e)(3) of Regulation S-X under the Securities Act.

 

The company is providing condensed consolidating financial information for SEECO, SEPCO, and SES, its subsidiaries that were guarantors of the Company’s registered public debt and outstanding senior notes, and for its other subsidiaries that are not guarantors of such debt for the three months ended March 31, 2013, as applicable. The company has not provided comparative financial statements for 2014 because all guarantees were released in 2013. The Company has not presented separate financial and narrative information for each of the former subsidiary guarantors because it believes that such financial and narrative financial information would not provide any additional information that would be material in evaluating the sufficiency of the guarantees. The following condensed consolidating financial information summarizes the results of operations, financial position and cash flow for the Company’s former guarantor and other subsidiaries.

 

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

 

The following updates information as to Southwestern Energy Company’s financial condition provided in our 2013 Annual Report on Form 10-K and analyzes the changes in the results of operations between the three-month periods ended March 31, 2014 and 2013. For definitions of commonly used natural gas and oil terms used in this Form 10-Q, please refer to the “Glossary of Certain Industry Terms” provided in our 2013 Annual Report on Form 10-K.

 

The following discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those anticipated in forward-looking statements for many reasons, including the risks described in the “Cautionary Statement About Forward-Looking Statements” in the forepart of this Form 10-Q, in Item 1A, “Risk Factors” in Part I and elsewhere in our 2013 Annual Report on Form 10-K, and Item 1A, “Risk Factors” in Part II in this Form 10-Q and any other Form 10-Q filed during the fiscal year. You should read the following discussion with our unaudited condensed consolidated financial statements and the related notes included in this Form 10-Q.

 

OVERVIEW

 

Background

 

Southwestern Energy Company is an independent energy company engaged in natural gas and oil exploration, development and production, or E&P. We are also focused on creating and capturing additional value through our natural gas gathering and marketing businesses, which we refer to as Midstream Services. We operate principally in two segments: E&P and Midstream Services.   

 

Our primary business is the exploration for and production of natural gas and oil, with our current operations being focused within the United States.  We are actively engaged in exploration and production activities in Arkansas, where we are targeting the unconventional gas reservoir known as the Fayetteville Shale, in Pennsylvania, where we are targeting the unconventional gas reservoir known as the Marcellus Shale, and to a lesser extent in Texas and in Arkansas and Oklahoma in the Arkoma Basin. The Company also actively seeks to find and develop new oil and natural gas plays with significant exploration and exploitation potential. In 2010, we commenced an exploration program in New Brunswick, Canada, which represents our first operations outside of the United States.

 

We are focused on providing long-term growth in the net asset value of our business. We derive the majority of our operating income and cash flow from the natural gas production of our E&P business and expect this to continue in the future. We expect that growth in our operating income and revenues will depend primarily on natural gas prices and our ability to increase our natural gas production. We expect our natural gas production volumes will continue to increase due to our ongoing development of the Fayetteville Shale and the Marcellus Shale. The price we expect to receive for our natural gas is a critical factor in the capital investments we make in order to develop our properties and increase our production.  In recent years, there has been volatility in natural gas prices as evidenced by New York Mercantile Exchange, or NYMEX, natural gas prices ranging from a high of $13.58 per MMBtu in 2008 to a low of $1.91 per MMBtu in April 2012.  Natural gas prices fluctuate due to a variety of factors we cannot control or predict. These factors, which include increased supplies of natural gas due to greater exploration and development activities, weather conditions, political and economic events, and competition from other energy sources, impact supply and demand for natural gas, which in turn determines the sales prices for our production. In addition to the factors identified above, the prices we realize for our production are affected by our hedging activities, transportation costs as well as locational differences in market prices.

 

Recent Financial and Operating Results

 

We reported net income of $194.2 million for the three months ended March 31, 2014, or $0.55 per diluted share, compared to a net income of $127.5 million, or $0.36 per diluted share, for the comparable period in 2013.

 

Our natural gas and oil production increased to 182.0 Bcfe for the three months ended March 31, 2014, up 23% from 147.8 Bcfe for the three months ended March 31, 2013. The 34.2 Bcfe increase in our first quarter 2014 production was primarily due to a 34.5 Bcf increase in production from our Marcellus Shale properties and a net 0.3 Bcf decrease in production from our other properties.  The average price realized for our gas production, including the effects of hedges, increased 23% to $4.19 per Mcf for the three months ended March 31, 2014 compared to $3.42 per Mcf for the same period in 2013.

 

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Our E&P segment reported operating income of $352.1 million for the three months ended March 31, 2014, up from operating income of $175.8 million for the three months ended March 31, 2013.  Operating income for the three months ended March 31, 2014 increased $176.3 million primarily as a result of the revenue impact of our 23%, or 34.2 Bcfe, increase in production and 23%, or $0.77, increase in our average realized natural gas prices, which more than offset the $113.8 million increase in operating costs and expenses that resulted from increased activity levels.

 

Operating income for our Midstream Services segment was $82.6 million for the three months ended March 31, 2014, up from $76.3 million for the three months ended March 31, 2013, primarily due to an increase of $12.4 million in gas gathering revenues and an increase of $3.0 million in the margin generated from our natural gas marketing activities, which was partially offset by a $9.1 million increase in operating costs and expenses associated with an increase in natural gas volumes gathered, exclusive of natural gas purchase costs.

 

Capital investments were $541.9 million for the three months ended March 31, 2014, of which $498.9 million was invested in our E&P segment, compared to $518.1 million for the same period of 2013, of which $475.3 million was invested in our E&P segment.

 

 

 

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RESULTS OF OPERATIONS

 

The following discussion of our results of operations for our segments is presented before intersegment eliminations. We evaluate our segments as if they were stand alone operations and accordingly discuss their results prior to any intersegment eliminations. Interest expense, income tax expense and stock-based compensation are discussed on a consolidated basis.

 

 

 

 

Revenues

 

Revenues for our E&P segment were $801.8 million for the three months ended March 31, 2014, up $290.2 million, or 57%, compared to the same period in 2013.   The increase in revenues was primarily due to higher realized prices and higher natural gas production volumes of $175.3 million and $117.7 million, respectively. We expect our natural gas production volumes to continue to increase due to our development and growth of our shale properties.  Natural gas prices are difficult to predict and subject to wide price fluctuations. As of March 31, 2014, we had hedged 348.6 Bcf of our remaining 2014 natural gas production and 119.5 Bcf of our 2015 natural gas production to limit our exposure to price fluctuations. We refer you to Note 7 to the unaudited condensed consolidated financial statements included in this Form 10-Q and to the discussion of “Commodity Prices” provided below for additional information.

Production

 

For the three months ended March 31, 2014, our natural gas and oil production increased 23% to 182.0 Bcfe, up from 147.8 Bcfe from the same period in 2013, and was produced entirely by our properties in the United States. The 34.2 Bcfe increase in our 2014 production was primarily due to a 34.5 Bcf increase in production from our Marcellus Shale properties and a net 0.3 Bcf decrease in production from our other properties. Net production from our Fayetteville Shale and Marcellus Shale properties was 119.4 Bcf and 58.0 Bcf, respectively, for the three months ended March 31, 2014 compared to 118.9 Bcf and 23.5 Bcf, respectively, for the same period in 2013.

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Commodity Prices

 

The average price realized for our natural gas production, including the effects of hedges, increased to $4.19 per Mcf for the three months ended March 31, 2014, as compared to $3.42 for the same period in 2013. The increase was the result of a $1.75 per Mcf increase in average natural gas prices, excluding hedges.  Our hedges decreased the average realized natural gas price $0.44 per Mcf for the three months ended March 31, 2014 compared to an increase of $0.54 per Mcf for the same period in 2013. The average price realized for our natural gas production, excluding the effects of hedges, increased 61% to $4.63 per Mcf for the three months ended March 31, 2014, as compared to the same period in 2013.  We periodically enter into various hedging and other financial arrangements with respect to a portion of our projected natural gas and crude oil production in order to ensure certain desired levels of cash flow and to minimize the impact of price fluctuations, including fluctuations in locational basis differentials (we refer you to Note 7 to the unaudited condensed consolidated financial statements included in this Form 10-Q for additional discussion).

 

Our E&P segment receives a sales price for our natural gas at a discount to average monthly NYMEX settlement prices due to locational basis differentials, while transportation charges and fuel charges also reduce the price received.  Excluding the impact of hedges, the average price received for our natural gas production for the three months ended March 31, 2014 of $4.63 per Mcf was approximately $0.31 lower than the average monthly NYMEX settlement price, primarily due to locational basis differentials and transportation costs.  We protected approximately 47% of our natural gas production for the three months ended March 31, 2014 from the impact of widening basis differentials through our hedging activities and sales arrangements. Excluding the impact of hedging, we expect our total natural gas sales discount to NYMEX to be approximately $0.55 to $0.60 per Mcf for 2014.  At March 31, 2014, we had basis protected approximately 239 Bcf of our remaining 2014 expected natural gas production through financial hedging activities and physical sales arrangements at a differential to NYMEX natural gas prices of approximately ($0.11) per Mcf, excluding transportation and fuel charges.   Additionally, at March 31, 2014, we had basis protected approximately 74 Bcf of our 2015 expected natural gas production through financial hedging activities and physical sales arrangements.

 

In addition to the basis hedges discussed above, at March 31, 2014, we had NYMEX fixed price hedges in place on notional volumes of 348.6 Bcf of our remaining 2014 natural gas production at an average price of $4.35 per MMBtu and notional volumes of 119.5 Bcf of our 2015 natural gas production at an average price of $4.40 per MMBtu.    

 

Operating Income

 

Our E&P segment reported operating income of $352.1 million for the three months ended March 31, 2014, up from operating income of $175.8 million for the three months ended March 31, 2013.  Operating income for the three months ended March 31, 2014 increased $176.3 million primarily as a result of the revenue impact of our 23%, or 34.2 Bcfe, increase in production and 23%, or $0.77, increase in our average realized natural gas prices, which more than offset the $113.8 million increase in operating costs and expenses that resulted from increased activity levels.

 

Operating Costs and Expenses

 

Lease operating expenses per Mcfe for our E&P segment were $0.93 for the three months ended March 31, 2014 compared to $0.81 for the same period in 2013. The increase in lease operating expense per unit of production for the three months ended March 31, 2014 as compared to the same period of 2013, was primarily due to increase in gathering cost in our Marcellus Shale assets and an increase in compression costs. 

 

General and administrative expenses per Mcfe for our E&P segment were $0.25 for the three months ended March 31, 2014 compared to $0.21 for the same period in 2013 primarily due to an increase in personnel costs.  In total general and administrative expenses for our E&P segment were $46.4 million for the three months ended March 31, 2014 compared to $30.5 million for the same period in 2013, primarily due to increased personnel costs associated with the expansion of our E&P operations due to the continued development of our Fayetteville Shale assets and Marcellus Shale assets. 

 

Taxes other than income taxes per Mcfe were $0.13 for the three months ended March 31, 2014 and $0.12 for the three months ended March 31, 2013. Taxes other than income taxes per Mcfe vary from period to period due to changes in severance and ad valorem taxes that result from the mix of our production volumes and fluctuations in commodity prices. 

 

Our full cost pool amortization rate averaged $1.10 per Mcfe for the three months ended March 31, 2014 compared to $1.09 for the same period in 2013. The amortization rate is impacted by the timing and amount of reserve additions

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and the costs associated with those additions, revisions of previous reserve estimates due to both price and well performance, write-downs that result from full cost ceiling tests, proceeds from the sale of properties that reduce the full cost pool and the levels of costs subject to amortization.  We cannot predict our future full cost pool amortization rate with accuracy due to the variability of each of the factors discussed above, as well as other factors, including but not limited to the uncertainty of the amount of future reserves. 

 

Unevaluated costs excluded from amortization were $878.7 million at March 31, 2014 compared to $956.5 million at December 31, 2013. The decrease in unevaluated costs since December 31, 2013 primarily resulted from the move of previously unevaluated acreage to evaluated, slightly offset by 2014 capital investments related to unevaluated properties.  Unevaluated costs excluded from amortization at March 31, 2014 included $73.5 million related to our properties in Canada, compared to $72.3 million at December 31, 2013.

 

The timing and amount of production and reserve additions and revisions could have a material adverse impact on our per unit costs.

 

 

 

Revenues

 

Revenues from our marketing activities were up 83% to $1,095.7 million for the three months ended March 31, 2014.  For the three months ended March 31, 2014, the volumes marketed increased 20% and the price received for volumes marketed increased 53% compared to the same period in 2013. Increases and decreases in marketing revenues due to changes in commodity prices are largely offset by corresponding changes in gas purchase expenses. Of the total volumes marketed, production from our affiliated E&P operated wells accounted for 96% and 95% of the marketed volumes for the three months ended March 31, 2014 and 2013, respectively. 

 

Revenues from our gathering activities were up 10% to $133.7 million for the three months ended March 31, 2014. The increase in gathering revenues resulted primarily from a 9% increase in gas volumes gathered for the three months ended March 31, 2014 compared to the same period in 2013.  Gathering volumes, revenues and expenses for this segment are expected to continue to grow as reserves related to our shale properties are developed and production increases.

 

Operating Income

 

Operating income from our Midstream Services segment increased to $82.6 million for the three months ended March 31, 2014 compared to $76.3 million for the same period in 2013. Operating income was higher due to increases in gas volumes gathered which primarily resulted from our increase in E&P production volumes. The $6.3 million increase in operating income for the three months ended March 31, 2014 was primarily due to an increase of $12.4 million in gathering revenues and an increase of $3.0 million in the margin generated from our gas marketing activities, which was partially offset by a $9.1 million increase in operating costs and expenses associated with an increase in gas volumes gathered, exclusive of gas purchase costs.

 

The margin generated from gas marketing activities was $11.2 million for the three months ended March 31, 2014 compared to $8.2 million for the three months ended March 31, 2013. Margins are primarily driven by volumes of natural gas marketed and may fluctuate depending on the prices paid for commodities and the ultimate disposition of those commodities. We enter into hedging activities from time to time with respect to our natural gas marketing

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activities to provide margin protection. We refer you to Item 3, “Quantitative and Qualitative Disclosures about Market Risks” included in this Form 10-Q for additional information.

 

Interest Expense

 

Interest expense, net of capitalization, increased to $12.9 million for the three months ended March 31, 2014, compared to $9.0 million for the same period in 2013. The increase in interest expense, net of capitalization, for the three months ended March 31, 2014 was primarily due to a decrease in capitalized interest for the three months ended March 31, 2014.  We capitalized interest of $13.4 and $16.2 million for the three months ended March 31, 2014 and 2013, respectively.  The decrease in capitalized interest for the three months ending March 31, 2014 compared to the same period in 2013 was primarily due to a reduction in the Company’s weighted average interest rate and a decrease in our unevaluated property balance. 

 

Gain (Loss) on Derivatives

 

At March 31, 2014, our basis swaps, certain fixed price swaps, call options and interest rate swaps were not designated for hedge accounting treatment. Changes in the fair value of derivatives that are not designated as cash flow hedges are recorded in gain (loss) on derivatives. For the three months ended March 31, 2014, we recorded a loss on derivatives, net of settlement of $26.9 million related to fixed price call options not designated for hedge accounting treatment, a loss on derivatives, net of settlement of $22.6 million related to fixed price swaps not designated for hedge accounting, a loss on derivatives, net of settlement of $10.2 million related to the basis swaps not designated for hedge accounting treatment and a loss on derivatives, net of settlement of $2.2 million related to interest rate swaps not designated for hedge accounting treatment.  In general and without consideration of volatility or duration, as 2014 natural gas prices increase from current levels, the Company will recognize losses in future periods and, likewise, as 2014 natural gas prices decline from current levels, the Company will recognize gains in future periods on its derivative contracts not accounted for under hedge accounting prior to settlement.

 

Income Taxes

 

Our effective tax rates were 40.0% for the three months ended March 31, 2014 and 2013.  For the three months ended March 31, 2014, we recorded an income tax expense of $129.0 million compared to an income tax expense of $85.1 million for the same period in 2013.

 

Stock-Based Compensation Expense

 

We recognized expense of $4.5 million and capitalized $4.5 million for stock-based compensation during the three months ended March 31, 2014 compared to $3.0 million expense and $2.9 million capitalized for the comparable period in 2013. We refer you to Note 14 in the unaudited condensed consolidated financial statements included in this Form 10-Q for additional discussion of our equity based compensation plans.

 

New Accounting Standards

 

No significant accounting standards applicable to Southwestern Energy Company have been issued since those disclosed in our 2013 Annual Report on Form 10-K.

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LIQUIDITY AND CAPITAL RESOURCES

 

We depend primarily on internally-generated funds, our Credit Facility and funds accessed through debt and equity markets as our primary sources of liquidity.

 

For the remainder of 2014, assuming natural gas prices remain at current levels, we intend to draw on a portion of the funds available under our Credit Facility to fund our planned capital investments (discussed below under “Capital Investments”).  We refer you to Note 10 to the unaudited condensed consolidated financial statements included in this Form 10-Q and the section below under “Financing Requirements” for additional discussion of our Credit Facility.

 

Net cash provided by operating activities increased 64% to $608.9 million for the three months ended March 31, 2014 compared to $372.1 million for the same period in 2013, is primarily due to an increase in net income adjusted for non-cash expenses primarily resulting from increased revenues due to higher realized gas prices, higher natural gas production and gathering volumes, offset slightly by a decrease in changes in working capital. During the three months ended March 31, 2014, requirements for our capital investments were funded primarily from our cash generated by operating activities and cash and cash equivalents. For the three months ended March 31, 2014, cash generated from our operating activities funded 100% of our cash requirements for capital investments and 77% for the three months ended March 31, 2013.

 

We believe that our operating cash flow, cash equivalents, and available funds under our Credit Facility will be adequate to meet our capital and operating requirements for 2014. The credit status of the financial institutions participating in our Credit Facility could adversely impact our ability to borrow funds under the Credit Facility. While we believe all of the lenders under the facility have the ability to provide funds, we cannot predict whether each will be able to meet its obligation.

 

Our cash flow from operating activities is highly dependent upon the market prices that we receive for our natural gas and oil production, including transportation and regional basis differentials. Natural gas and oil prices are subject to wide fluctuations and are driven by market supply and demand factors which are impacted by the overall state of the economy. The price received for our production is also influenced by our commodity hedging activities, as more fully discussed in Item 3, “Quantitative and Qualitative Disclosures about Market Risks” and Note 7 in the unaudited condensed consolidated financial statements included in this Form 10-Q. Our commodity hedging activities are subject to the credit risk of our counterparties being financially unable to complete the transaction. We actively monitor the credit status of our counterparties, performing both quantitative and qualitative assessments based on their credit ratings and credit default swap rates where applicable, and to date have not had any credit defaults associated with our transactions. However, any future failures by one or more counterparties could negatively impact our cash flow from operating activities.

 

Additionally, our short-term cash flows are dependent on the timely collection of receivables from our customers and partners. We actively manage this risk through credit management activities and through the date of this filing have not experienced any significant write-offs for non-collectable amounts. However, any sustained inaccessibility of credit by our customers and partners could adversely impact our cash flows.

 

Due to the above factors, we are unable to forecast with certainty our future level of cash flow from operations. Accordingly, we will adjust our discretionary uses of cash dependent upon available cash flow.

 

Capital Investments

 

Our capital investments were $541.9 million for the three months ended March 31, 2014 compared to $518.1 million for the comparable period in 2013.  Our E&P segment investments were $498.9 million and $475.3 million for the three months ended March 31, 2014 and 2013 respectively.  Our E&P segment capitalized internal costs of $81.3 million for the three months ended March 31, 2014 compared to $54.1 million for the comparable period in 2013. These internal costs were directly related to acquisition, exploration and development activities and are included as part of the cost of natural gas and oil properties. 

 

Our capital investments for 2014 are planned to be approximately $2.3 billion, consisting of $2.0 billion for E&P, $0.1  billion for Midstream Services and $0.2 billion for corporate and other purposes. Of the approximate $2.0 billion for E&P, we expect to allocate approximately $900 million to our Fayetteville Shale assets and approximately $760 million to our Marcellus Shale assets.  Our planned level of capital investments in 2014 is expected to allow us to continue our progress in the Fayetteville Shale and Marcellus Shale programs and explore and develop other existing natural gas and oil properties and generate new drilling prospects. Our remaining 2014 capital investment program is

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expected to be funded through cash flow from operations and borrowings under our Credit Facility. The planned capital program for 2014 is flexible and can be modified.  We will reevaluate our proposed investments as needed to take into account prevailing market conditions and we could change our planned investments.

 

Financing Requirements

 

Our total debt outstanding was $1.8 billion at March 31, 2014 compared to $2.0 billion at December 31, 2013.  On December 16, 2013, the Company entered into a new Credit Agreement (“Credit Facility”), which exchanged our previous revolving credit facility.  Under the Credit Facility, we have a borrowing capacity of  $2.0 billion. The Credit Facility has a maturity date in December 2018 and options for two one-year extensions with participating lender approval.  The amount available under the Credit Facility may be increased by  $500.0  million upon the Company’s agreement with its participating lenders.

 

The interest rate on our Credit Facility is calculated based upon our public debt rating and is currently 150 basis points over LIBOR. Our publicly traded notes are rated BBB- by Standard and Poor’s and we have a long term debt rating of Baa3 by Moody’s. Any downgrades in our public debt ratings could increase our cost of funds under the Credit Facility.

 

Our Credit Facility contains covenants which impose certain restrictions on us. Under the Credit Facility, we must keep our total debt at or below 60% of our total adjusted book capital. This financial covenant with respect to capitalization percentages excludes the effects of any full cost ceiling impairments (after December 31, 2011), certain non-cash hedging activities and our pension and other postretirement liabilities. Therefore, under our Credit Facility provision, our capital structure as of March 31, 2014, was 27% debt and 73% equity. We were in compliance with all of the covenants of our Credit Facility as of March 31, 2014. Although we do not anticipate any violations of our financial covenants, our ability to comply with those covenants is dependent upon the success of our exploration and development program and upon factors beyond our control, such as the market prices for natural gas and oil.  If we are unable to borrow under our Credit Facility, we may have to decrease our capital investment plans.

 

At March 31, 2014, our capital structure consisted of 32% debt and 68% equity (exclusive of cash and cash equivalents) and $18.7 million in cash and cash equivalents, compared to 35% debt and 65% equity and $22.9 million in cash and cash equivalents at December 31, 2013. Equity at March 31, 2014 included an accumulated other comprehensive loss of $18.6 million related to our hedging activities and a $9.5 million related to our pension and other postretirement liabilities. The amount recorded in equity for our hedging activities is based on current market values for our hedges at March 31, 2014 and does not necessarily reflect the value that we will receive or pay when the hedges are ultimately settled, nor does it take into account revenues to be received associated with the physical delivery of sales volumes hedged.

 

Our hedges allow us to ensure a certain level of cash flow to fund our operations.  At April 28, 2014, we had NYMEX commodity price hedges in place on 348.6 Bcf of our remaining targeted 2014 natural gas production and 157.0 Bcf of our expected 2015 natural gas production.  The amount of long-term debt we incur will be largely dependent upon commodity prices and our capital investment plans.

 

Contractual Obligations and Contingent Liabilities and Commitments

 

We have various contractual obligations in the normal course of our operations and financing activities. There have been no material changes to our contractual obligations from those disclosed in our 2013 Annual Report on Form 10-K.

 

Contingent Liabilities and Commitments

 

In the first quarter of 2010, the Company was awarded exclusive licenses by the Province of New Brunswick in Canada to conduct an exploration program covering approximately 2.5 million acres in the province. The licenses require the Company to make certain capital investments in New Brunswick of approximately $47.0 million Canadian dollars in the aggregate over a three year period. In order to obtain the licenses, the Company provided promissory notes payable on demand to the Minister of Finance of the Province of New Brunswick with an aggregate principal amount of $44.5 million Canadian dollars. The promissory notes secure the Company's capital expenditure obligations under the licenses and are returnable to the Company to the extent the Company performs such obligations. If the Company fails to fully perform, the Minister of Finance may retain a portion of the applicable promissory notes in an amount equal to any deficiency. The Company commenced its Canada exploration program in 2010 and, as of March 31, 2014 has invested $42.2 million Canadian dollars, or $38.2 million USD, in New Brunswick towards the Company’s commitment.  In December 2012, the Company received two one-year extensions to our exploration license agreements,

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the second of which will expire on March 16, 2015.  No liability has been recognized in connection with the promissory notes due to the Company’s investments in New Brunswick as of March 31, 2014 and its future investment plans. 

 

Substantially all of our employees are covered by defined pension and postretirement benefit plans. As of March 31, 2014, the Company has contributed $3.0 million to the pension plan,  and expects to contribute an additional $9.0 million to the pension plan in 2014. At March 31, 2014, we recognized a liability of $16.8 million as a result of the underfunded status of our pension and other postretirement benefit plans compared to a liability of $16.2 million at December 31, 2013.

 

We are subject to litigation, claims and proceedings (including with respect to environmental matters) that arise in the ordinary course of business. Management believes, individually or in aggregate, such litigation, claims and proceedings will not have a material adverse impact on our financial position, results of operations, or cash flows, but these matters are subject to inherent uncertainties and management’s view may change in the future.  If an unfavorable final outcome were to occur, there exists the possibility of a material impact on our financial position, results of operations or cash flows for the period in which the effect becomes reasonably estimable. We accrue for such items when a liability is both probable and the amount can be reasonably estimated.  For further information regarding commitments and contingencies, we refer you to Note 11 in the unaudited condensed consolidated financial statements included in this Form 10-Q.

 

Working Capital

 

We had negative working capital of $152.1 million at March 31, 2014 and negative working capital of $43.8 million at December 31, 2013. Current assets increased by $38.9 million during the three months ended March 31, 2014 primarily due to a $78.0 million increase in accounts receivable, a $23.4 million increase in other current assets and a $1.1 million increase in inventory.  These increases were partially offset by a $59.4 million decrease in current hedging asset and a $4.2 million decrease in cash and cash equivalents. Current liabilities increased by $147.1 million during the three months ended March 31, 2014 primarily as a result of a $135.3 million increase in accounts payable and a $68.5 million increase in other current liabilities. These increases were partially offset by a $24.4 million decrease in current deferred income taxes, $19.4 million decrease in interest payable and a $12.9 million decrease in taxes payable. We maintain access to funds that may be needed to meet capital requirements through our Credit Facility described in “Financing Requirements” above.

 

Natural Gas in Underground Storage

 

We record our natural gas stored in inventory that is owned by the E&P segment at the lower of weighted average cost or market. The natural gas in inventory for the E&P segment is used primarily to supplement production in meeting the segment’s contractual commitments, especially during periods of colder weather. In determining the lower of cost or market for storage gas, we utilize the natural gas futures market in assessing the price we expect to be able to realize for our natural gas in inventory. A decline in the future market price of natural gas could result in write-downs of our natural gas in underground storage carrying cost.

 

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

 

Market risks relating to our operations result primarily from the volatility in commodity prices, basis differentials and interest rates, as well as credit risk concentrations. We use natural gas and crude oil swap agreements and options and interest rate swaps to reduce the volatility of earnings and cash flow due to fluctuations in the prices of natural gas and oil and in interest rates. Our Board of Directors has approved risk management policies and procedures to utilize financial products for the reduction of defined commodity price risk.  The Board of Directors has approved our use of financial products for the reduction of interest rate risks.  These policies prohibit speculation with derivatives and limit swap agreements to counterparties with appropriate credit standings.

 

Credit Risk

 

Our financial instruments that are exposed to concentrations of credit risk consist primarily of trade receivables and derivative contracts associated with commodities trading. Concentrations of credit risk with respect to receivables are limited due to the large number of our customers and their dispersion across geographic areas. No single customer accounted for greater than 10% of revenues for the three months ended March 31, 2014.  See “Commodities Risk” below for discussion of credit risk associated with commodities trading.

 

Interest Rate Risk

 

At March 31, 2014, we had approximately $1.8 billion of total debt with a weighted average interest rate of 5.12%. Our Credit Facility has a floating interest rate (1.62% at March 31, 2014).  At March 31, 2014, we had borrowings outstanding of $160.2 million under our Credit Facility. 

 

Interest rate swaps may be used to adjust interest rate exposures when deemed appropriate. At March 31, 2014, the Company had a net derivative asset position of $0.8 million related to interest-rate swaps. A 10% increase or decrease in interest rates would not result in a material increase or decrease in the aggregate fair value of outstanding interest-rate swap agreements. For a summary of the Company’s open interest-rate derivative positions, we refer you to Note 7 to the unaudited condensed consolidated financial statements included in this Form 10-Q.

 

Commodities Risk

 

We use over-the-counter natural gas and crude oil swap agreements and options to hedge sales of our production against the inherent price risks of adverse price fluctuations or locational pricing differences between a published index and the NYMEX futures market. These swaps and options include (1) transactions in which one party will pay a fixed price (or variable price) for a notional quantity in exchange for receiving a variable price (or fixed price) based on a published index (referred to as price swaps), (2) transactions in which parties agree to pay a price based on two different indices (referred to as basis swaps) and (3) the purchase and sale of index-related puts and calls (collars) that provide a “floor” price, below which the counterparty pays funds equal to the amount by which the price of the commodity is below the contracted floor, and a “ceiling” price above which we pay to the counterparty the amount by which the price of the commodity is above the contracted ceiling.

 

The primary market risks relating to our derivative contracts are the volatility in market prices and basis differentials for natural gas and crude oil. However, the market price risk is offset by the gain or loss recognized upon the related sale or purchase of the natural gas or sale of the oil that is hedged. Credit risk relates to the risk of loss as a result of non-performance by our counterparties. The counterparties are primarily major commercial banks, investment banks and integrated energy companies which management believes present minimal credit risks. The credit quality of each counterparty and the level of financial exposure we have to each counterparty are closely monitored to limit our credit risk exposure. Additionally, we perform both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable. We have not incurred any counterparty losses related to non-performance and do not anticipate any losses given the information we have currently. However, given the recent volatility in the financial markets, we cannot be certain that we will not experience such losses in the future.

 

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Exploration and Production

 

The following table provides information about our financial instruments that are sensitive to changes in commodity prices and that are used to hedge prices for natural gas production. The table presents the notional amount in Bcf, the weighted average contract prices and the fair value by expected maturity dates. At March 31, 2014, the net fair value of our financial instruments related to natural gas production was a $73.0 million liability.

 

 

 

At March 31, 2014, our basis swaps, certain fixed price swaps, call options and interest rate swaps were not designated for hedge accounting treatment. Changes in the fair value of derivatives that are not designated as cash flow hedges are recorded in gain (loss) on derivatives. For the three months ended March 31, 2014, we recorded a loss on derivatives, net of settlement of $26.9 million related to fixed price call options not designated for hedge accounting treatment, a loss on derivatives, net of settlement of $22.6 million related to fixed price swaps not designated for hedge accounting, a loss on derivatives, net of settlement of $10.2 million related to the basis swaps not designated for hedge accounting treatment, a loss on derivatives, net of settlement of $2.2 million related to interest rate swaps not designated for hedge accounting treatment and a loss of $1.9 million related to the change in estimated ineffectiveness of our cash flow hedges. Typically, our hedge ineffectiveness results from changes at the end of a reporting period in the price differentials between the index price of the derivative contract, which is primarily a NYMEX price, and the index price for the point of sale for the cash flow that is being hedged.    

 

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Item 4. Controls and Procedures.

 

Evaluation of  Disclosure Controls and Procedures

 

We have performed an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d 15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act). Our disclosure controls and procedures are the controls and other procedures that we have designed to ensure that we record, process, accumulate and communicate information to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures and submission within the time periods specified in the SEC’s rules and forms. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those determined to be effective can provide only a level of reasonable assurance with respect to financial statement preparation and presentation. Based on the evaluation, our management, including our Chief Executive Officer and Chief Financial Officer, concluded that our disclosure controls and procedures were effective as of March 31, 2014 at the reasonable assurance level.

 

Changes in Internal Control over Financial Reporting

 

There were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the three months ended March 31, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II - OTHER INFORMATION

 

ITEM 1. LEGAL PROCEEDINGS. 

 

We are subject to laws and regulations relating to the protection of the environment. Our policy is to accrue environmental and cleanup related costs of a non-capital nature when it is both probable that a liability has been incurred and when the amount can be reasonably estimated. Management believes any future remediation or other compliance related costs will not have a material effect on our financial position, results of operations, and cash flows.

 

Tovah Energy

 

In February 2009, SEPCO was added as a defendant in a case then styled Tovah Energy, LLC and Toby Berry-Helfand v. David Michael Grimes, et, al., pending in the 273rd District Court in Shelby County, Texas. By the time of trial in December 2010, Ms. Berry-Helfand (the only remaining plaintiff) alleged that, in 2005, she provided SEPCO with proprietary data regarding two prospects in the James Lime formation pursuant to a confidentiality agreement and that SEPCO refused to return the proprietary data to the plaintiff, subsequently acquired leases based upon such proprietary data and profited therefrom. Among other things, she alleged various statutory and common law claims, including, but not limited to, claims of misappropriation of trade secrets, violation of the Texas Theft Liability Act, breach of fiduciary duty and confidential relationships, various fraud based claims and breach of contract, including a claim of breach of a purported right of first refusal on all interests acquired by SEPCO between February 2005 and February 2006. She also sought disgorgement of SEPCO’s profits. A former associate of the plaintiff intervened in the matter claiming to have helped develop the prospect years earlier.

 

The jury found in favor of the plaintiff and the intervenor with respect to all of the statutory and common law claims and awarded $11.4 million in compensatory damages but no special, punitive or other damages. Separately, the jury determined that SEPCO’s profits for purposes of disgorgement, if ordered as a remedy, were $381.5 million. (Disgorgement of profits is an equitable remedy determined by the judge, and it is within the judge’s discretion to award none, some or all of unlawfully obtained profits.) In August 2011, a judgment was entered pursuant to which the plaintiff and the intervenor were entitled to recover approximately $11.4 million in actual damages and approximately $23.9 million in disgorgement as well as prejudgment interest and attorneys’ fees, which currently are estimated to be up to $8.9 million, and all costs of court of the plaintiff and intervenor.

 

Both sides appealed and in July 2013, the Tyler Court of Appeals ordered that (1) the judgment awarding the plaintiff and the intervenor $23.9 million as disgorgement of illicit gains be reversed and judgment rendered that they take nothing, (2) the award of $11.4 million for actual damages, insofar as it is based on the jury’s findings of breach of fiduciary duty, fraud, breach of contract, and theft of trade secret is reversed and judgment rendered that the plaintiff and the intervenor take nothing under those theories of recovery, (3) the award of $11.4 million to the plaintiff and the intervenor as damages for misappropriation of trade secret is affirmed, (4) the case be remanded to the trial court for a determination and award of attorney’s fees for SEPCO as the prevailing party under the Texas Theft Liability Act, and (5) in all other respects, the judgment is affirmed. All parties petitioned for rehearing. The Tyler Court of Appeals denied rehearing in November 2013.

 

SEPCO filed a petition for review in the Supreme Court of Texas in February 2014. The plaintiff and the intervenor filed cross-petition for review in April 2014, but conditioned their filing on the court’s granting SEPCO’s petition for review; i.e., if the court denies SEPCO’s petition for review, then the plaintiff and the intervenor are not seeking further review of the court of appeals’ judgment. Based on the Company’s understanding and judgment of the facts and merits of this case, including appellate matters, and after considering the advice of counsel, the Company has determined that, although reasonably possible, a materially adverse final outcome to this action is not probable. As such, the Company has not accrued any amounts with respect to this action. If the Supreme Court declines to hear the case or affirms all aspects of the court of appeals’ judgment, then SEPCO would owe the $11.4 million in damages, plus interest and attorneys fees, offset by any award of attorneys’ fees for its prevailing on the theft count. The Company’s assessment may change in the future due to occurrence of certain events, such as the result of the petition or petitions for review at the Supreme Court of Texas, and such a re-assessment could lead to the determination that the potential liability is probable and could be material to the Company’s results of operations, financial position or cash flows. 

 

Other

The Company is subject to various litigation, claims and proceedings that have arisen in the ordinary course of business, such as for alleged breaches of contract, miscalculation of royalties and pollution, contamination or nuisance. Management believes that such litigation, claims and proceedings, individually or in aggregate and after taking into

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account insurance, are not likely to have a material adverse impact on our financial position, results of operations or cash flows. Many of these matters are in early stages, so the allegations and the damage theories have not been fully developed, and all subject to inherent uncertainties; therefore, management’s view may change in the future. If an unfavorable final outcome were to occur, there exists the possibility of a material impact on the Company’s financial position, results of operations or cash flows for the period in which the effect becomes reasonably estimable. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. 

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ITEM 1A. RISK FACTORS. 

 

There were no additions or material changes to the Company’s risk factors as disclosed in Item 1A of Part I in the Company’s 2013 Annual Report on Form 10-K.

 

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

 

Not applicable.

 

ITEM 3. DEFAULTS UPON SENIOR SECURITIES.

 

Not applicable.

 

ITEM 4. MINE SAFETY DISCLOSURES.

 

Our sand mining operations, in support of our E&P business, are subject to regulation by the Federal Mine Safety and Health Administration under the Federal Mine Safety and Health Act of 1977. Information concerning mine safety violations or other regulatory matters required by section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.106) is included in Exhibit 95.1 to this Form 10-Q.

 

ITEM 5. OTHER INFORMATION.

 

Not applicable.

 

ITEM 6. EXHIBITS.

 

(31.1)Certification of CEO filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 

(31.2)Certification of CFO filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 

(32.1)Certification of CEO and CFO furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

(95.1)Mine Safety Disclosure.

 

(101.INS)Interactive Data File Instance Document.

 

(101.SCH)Interactive Data File Schema Document.

 

(101.CAL)Interactive Data File Calculation Linkbase Document.

 

(101.LAB)Interactive Data File Label Linkbase Document.

 

(101.PRE)Interactive Data File Presentation Linkbase Document.

 

(101.DEF)Interactive Data File Definition Linkbase Document.

 

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Signatures

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

 

 

 

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